Chappell, David (Martin Towns BP) | Stapley, Jon (Martin Towns BP) | Rashid, Bilal (Martin Towns BP) | Andrews, William J. (Nalco Champion) | Kiani, Mojtaba (Nalco Champion) | Salehi, Mehdi (Nalco Champion)
This paper describes the successful execution of an inter-well field trial to test a novel reservoir-triggered polymer technology (the Polymer) which has been proven to mitigate two of the major operational and economic challenges facing polymer injection for enhanced oil recovery (EOR), particularly in the offshore environment. The challenges of shear degradation and reduced injectivity are overcome by delaying the development of viscosity until the Polymer is in the reservoir.
The field trial was conducted in an onshore sandstone oil field in Texas. The 1,000 ppm Polymer solution was injected at rates of 500 to 900 bbl/d into a 10-ft interval of low water permeability (50-100 mD) under matrix conditions. To demonstrate development of its expected viscosity in the reservoir, the growing Polymer bank was sampled from an existing producer. Pressure Transient Analysis (PTA) was used to confirm the deep-reservoir behaviour of the Polymer.
Field data demonstrates that the Polymer behaves as intended. The viscosity of the produced Polymer samples corresponds to the target viscosity as determined from surface activation of the Polymer at the same concentration. This confirms the shear-stability of the Polymer in its un-triggered form. In addition, the injection pressures were no greater than expected and significantly lower than the expected injection pressures, under matrix conditions, for an equivalent partially-hydrolysed polyacrylamide (HPAM). PTA indicates a bank of fluid of increased viscosity some distance from the injector, as designed.
Leitenmueller, Verena (Mining University Leoben) | Wenzina, Johannes (Technical University Vienna) | Kadnar, Rainer (OMV Exploration & Production GmbH) | Jamek, Karl (OMV Exploration & Production GmbH) | Hofstaetter, Herbert (Mining University Leoben)
Nowadays, the injection of dilute hydrolyzed polyacrylamide (HPAM) solutions after water flooding operations is a promising tertiary recovery method. However, the treatment of produced water containing breakthrough polymer plays a challenging aspect in the oil and gas industry. Ensuring good filterability of the produced water for further usage, either pressure maintenance or EOR application, is still a critical issue. Polymer loads in the produced water need to be expected, which can massively influence the separation efficiency of the water treatment system. Especially, the handling of polymer-containing water streams and finding the appropriate technology for the treatment, chemically or mechanically, has a decisive influence on performing a full-field roll out of polymer flooding activities.
Aim of this work was to study the impact of back-produced polymer on the water treatment process and to reach the desired injection water quality. Therefore a water treatment plant in pilot scale was used. The unit simulates the main process steps of the water treatment plant Schönkirchen in the Vienna Basin (corrugated plate interceptor, dissolved gas flotation unit, and nutshell filter). The maximum back-produced polymer concentration, which can be handled within the system, was determined. Two different chemical sets (coagulant and flocculant) were tested, regarding their oil and solids removal ability, in presence of different polymer concentrations.
At the end of the field study, one of these chemical sets was found, having a hydrocarbon removal efficiency of around 99% in presence of 30 ppm HPAM inlet concentration. Using this set, good removal efficiency and no plugging of the nutshell filter was observed even at high polymer concentrations. The other set led to plugging of the filtration system at relative low polymer concentrations of 8 ppm HPAM and the removal efficiency of hydrocarbons as well as polymer was poor. Based on these results, it can be assumed that the processes of the water treatment plant Schönkirchen are not negatively affected in the presence of up to 30 ppm polymer load in the inlet water stream.
Dupuis, Guillaume (SNF) | Antignard, Sebastien (SNF) | Giovannetti, Bruno (SNF) | Gaillard, Nicolas (SNF) | Jouenne, Stephane (Total) | Bourdarot, Gilles (Total) | Morel, Danielle (Total) | Zaitoun, Alain (Poweltec)
A great number of Middle East fields have too harsh reservoir conditions (high temperature, high salinity) for conventional EOR polymers used as mobility control agents. Traditional synthetic polymers such as partially hydrolyzed polyacrylamide (HPAM) are not thermally stable.
At temperatures above 70°C, acrylamide moieties hydrolyze to acrylate groups which ultimately may lead to precipitation and total loss of viscosifying power. Thermal stability can be improved by incorporating specific monomers such as ATBS or NVP. However, their polymerization reactivity can cause some compositional drift and limit their molecular weight / viscosifying power. Compared to HPAM, they will require a higher dosage and higher cost.
In this study, we present thermal stability and propagation behavior of a new class of synthetic polymers with high thermal stability. In harsh conditions of Middle East brines, with salinity ranging from sea water to 220 g/L TDS, they present excellent thermal stability until temperature as high as 140°C. Adsorption and mobility reduction were evaluated through coreflood experiments using carbonate cores and Clashach sandstone cores, with permeability ranging between 100mD and 700mD. Mobility and permeability reductions indicate a good propagation in both types of rocks.
The development of this new polymer is a major breakthrough to overcome the current limits of polymer EOR applications in harsh reservoir conditions. Moreover, molecular weights can be tailored from low to high molecular weights depending on reservoir permeability. Further work is needed to evaluate resistance to mechanical degradation, salt tolerance and adsorption in carbonates and sandstones.
Gheneim, Thaer (Schlumberger) | Azancot, Annalyn (Schlumberger) | Acosta, Tito (Ecopetrol) | Zapata, Jose Francisco (Ecopetrol) | Chaparro, Carlos (Ecopetrol) | Lobo, Adriano (Ecopetrol) | Jimenez, Ana María (Ecopetrol) | Perez, Gerson (Ecopetrol)
Casabe field reservoir characteristics are multilayer, geological complexity, vertical/areal heterogeneity and commingled production. Due large difference in mobility between oil and water (M ~ 20) and the maturity of water flooding, several operational problems have arisen, such as, increase of water cut, channeling, sand production, etc. These problems together with the high remaining reserves and identification of bypassed oil, were the main reasons to evaluate EOR process as a solution to increase the recovery factor.
A reduced Cycle Time was created to reduce the time from design to full field implementation which involves the following phases: Screening/Conceptual Design, Pilot Design, Drilling-Workover and Facilities, Operation & Surveillance, Pilot Expansion, Full Field Development Plan, Reserves & FID. This strategy is based on multitask parallel process to allow fast track decision making and activities execution for a fast pilot implementation, which allowed to implement the EOR pilot in 24 months form the screening to pilot Operation & Surveillance. After the screening, polymer flooding was considered for mobility ratio modification to improve sweep efficiency and therefore increase RF.
The best producer layers were selected, based on the areal continuity and residual oil in place, as target sands for polymer injection. One pattern was selected for the pilot. Laboratory tests, along with reservoir simulation confirmed the potential of chemical EOR in the selected sands and pilot area. Polymer injection was performed in four injector wells of the selected pattern. The polymer flooding process was monitored in the central producer and in the eight producers of the second line.
A surveillance plan was implemented to collect the information required to evaluate, with the lowest uncertainty, the results of this pilot. An observation well was drilled to monitored changes in oil saturation. The surveillance plan was critical to be able to control the polymer injection process, to have a proper technical evaluation of the pilot and to optimize costs during the future expansion and full field implementation. Polymer flooding have increased the RF on the selected area.
The fast-tracking strategy for an EOR project execution was successfully implemented in Casabe Field and the pilot was delivered in 2 years proving the concept of 5-year road map it is possible. The reduced Cycle Time (5-year Road Map) could be used as reference for implementation of new EOR pilots in other fields in shorter time and optimizing resources.
The workflows used and the analysis procedures created for this pilot could be used as reference for the implementation of future pilots in fields with similar characteristics.
Kohda, Atsuro (INPEX Corporation) | Bellah, Sameer (ZADCO) | Shibasaki, Toshiaki (ZADCO) | Farhan, Zahra Al (ZADCO) | Shibayama, Akira (INPEX Corporation) | Hamami, Mohamed Al (ZADCO) | Jasmi, Sami Al (ZADCO)
The understanding of heterogeneous rock properties especially high-permeability streaks is very important to predict fluid behavior in carbonate reservoirs. An Upper Jurassic reservoir in "Field A" has been producing for 30 years with different production scheme such as crestal water and gas injection at the different stage. The observed water/gas breakthrough and the evolution trend in water cut/GOR indicate reservoir heterogeneity caused by geological complexity. To replicate such complicated fluids behavior in reservoir model, the characterization study for high-permeability streaks was conducted.
Multiple data sources were used to identify and characterize high-permeability streaks.
Interpreted injected gas/water sweep intervals utilizing cased-hole production logging. Identified potential high-permeable lithofacies and its stratigraphic positions by detailed core and thin section descriptions with petrophysical observations. Defined high-permeability streaks based on the integrated interpretation of multiple data sources. Characterized the high-permeability streaks in reservoir model with excess flow capacity estimated from model and well-test permeability.
Interpreted injected gas/water sweep intervals utilizing cased-hole production logging.
Identified potential high-permeable lithofacies and its stratigraphic positions by detailed core and thin section descriptions with petrophysical observations.
Defined high-permeability streaks based on the integrated interpretation of multiple data sources.
Characterized the high-permeability streaks in reservoir model with excess flow capacity estimated from model and well-test permeability.
This study revealed that multiple types of high-permeability streaks present in the reservoir. In particular, it was recognized that a specific thin layer comprises stromatoporoid (epibenthic calcified sponges) patch reef deposits acts as the main contributor for fluids movement. This paper shows how to characterize the high-permeability streaks in reservoir model focusing on stromatoporoid lithofacies.
Thickness of stromatoporoid lithofacies shows heterogeneous variation of 0 to 14 feet. The complex pore system in stromatoporoid lithofacies associated with heterogeneously distributed skeletal fragments with centimeter-scale makes difficulty for capturing accurate permeability from conventional plug measurement. The plug permeability was generally underestimated comparing with actual flow capacity estimated from well-test. Hence the modeled permeability which generated from porosity-permeability correlation coming from plug measurement was required further conditioning based on the pre-established concept for high-permeability streaks.
To fill the gap between modelled and well-test permeability-thickness (KH) i.e. excess KH, the relevance between excess KH and stromatoporoid lithofacies was investigated. As a result, it was found that the zonal well-test KH increases as stromatoporoid lithofacies thickness (STR-H) increases, and there is a good correlation between STR-H and STR-KH estimated as "zonal well-test KH" minus "zonal modeled KH except stromatoporoid lithofacies intervals". Therefore, excess KH was allocated to only into the part of stromatoporoid lithofacies. The prepared STR-H map was directory transformed to STR-KH distributions by the revealed correlation. Through dynamic history matching, permeability distribution was iteratively modified by updating STR-H map in concordance with depositional concept.
Detailed observations and integrated interpretation for multiple data sources allowed identifying high-permeability streaks and establishment of a model workflow for representing its heterogeneity and associated permeability distribution. This workflow enabled geologically reasonable permeability conditioning and iterative model update in conjunction with the depositional concept during dynamic history matching.
Al-Sulaimani, Hanaa (Petroleum Development Oman) | Al-Rawahi, Zainab (Petroleum Development Oman) | Quesada, Conny Velazco (Petroleum Development Oman) | Al-Ghannami, Mohammed (Petroleum Development Oman) | Frumau, Mervin (Petroleum Development Oman) | Al-Hussaini, Azza (Petroleum Development Oman) | Hemink, Gijs (Petroleum Development Oman) | Nadeem, Muhammed (Petroleum Development Oman) | Khattak, Ali (Petroleum Development Oman) | Al-Hinai, Ghalib (Petroleum Development Oman) | Al-Mahrooqi, Majid (Petroleum Development Oman) | Al-Shidi, Maitham (Petroleum Development Oman) | Syed, Muhammad (Petroleum Development Oman)
Petroleum Development Oman (PDO) has commenced several Enhanced Oil Recovery (EOR) methods in the Sultanate of Oman to increase recovery from fields with challenging rock and fluid properties. Polymer flood is one of the mature EOR techniques that are currently operated in sandstone reservoirs in the South of Oman.
The reservoir under trial in this paper shares its OWC with another reservoir that has been developed through polymer flood. Although they both share similar fluids with viscosity of ~90cP, the reservoir under trial exhibits significant lower permeabilities, which poses a risk to injectivity. Furthermore, well completions with sand control have shown to be too detrimental to productivity which causes high sand production. This creates a challenge for the polymer flood from both the injectivity and sand control point of view. Thus, a pilot was designed with the following three objectives; test ability to sustain injectivity of polymer into the reservoir, monitor polymer efficiency, and evaluate operational impact on facilities due to sand production that is expected to increase with polymer flood.
The pilot was designed such that two patterns are drilled adjacent to each other where one will be used for the polymer flood and the other pattern serves as a backup in case the first pattern suffers from loss of injectivity or any unforeseen issues. The patterns are inverted five spots with an injector-producer spacing of 75m. The injectors are equipped with fiber optics for data acquisition and real time temperature and acoustic surveillance. The plan is to inject water until a baseline is established, which is then followed by polymer injection for up to one year.
Currently, the project is in the water injection phase where information and data are gathered such as injectivity, conformance, reservoir connectivity in addition to fluids production baseline establishment. This paper presents those findings from the water injection phase in addition to design aspects for the polymer phase.
Haroun, Mohamed (Petroleum Institute) | Mohammed, Abdul Moqtadir (Petroleum Institute) | Somra, Bharat (Petroleum Institute) | Punjabi, Soham (Petroleum Institute) | Temitope, Ajayi (Petroleum Institute) | Yim, Youngsun (Petroleum Institute) | Anastasiou, Stavroula (Petroleum Institute) | Baker, Jassim Abu (Petroleum Institute) | Haoge, Liu (Petroleum Institute) | Al Kobaisi, Mohammed (Petroleum Institute) | Karakas, Metin (University of Southern California) | Aminzadeh, Fred (University of Southern California) | Corova, Francisco (Petroleum Institute)
Surfactant Foam assisted CO2 EOR, though getting traction for its environomic mobility control potential, faces numerous challenges for deployment in HPHTHS heterogeneous carbonate reservoirs. Amongst the major challenges, the first is the lack of a surfactant formulation compatible with our carbonate reservoirs and the second is the absence of a foam and CO2 front monitoring tool either at laboratory or field scale.
In this study, a novel monitoring technique has been developed to track quality of the foam while core-flooding. This is essential to capture the onset formation, development rate and break-through of the said foam across varying length of core-plugs. This has been previously conducted in lab-scale by virtue of pressure response with or without expensive imaging methods. This tool complements the conventional method of studying pressure response with resistance measurements across the core allowing tracking of the foam generation and propagation. Various preconditioning smart brines (SB) were alternatively injected with the non-ionic surfactant APG, co-injected with gas, to generate foam
The foam generation, stability and breakthrough were studied as a function of salinity, ion composition and injected pore volumes of the various brines and surfactant. Core-plugs of 2 different rock types were flooded with 4 variations of smart brines at a constant flow rate. The tested formulations were ramped up from 2 to 8 pore volumes. The response of the ΔP/PV integrated with the Δρ/PV curves were analysed to detect foam generation and breakthrough. This allowed an immediate characterization of the foam performance providing capability of tracking the foam formation/dissipation across the length of the core-plugs, essential for compatible successful foam formulation.
This novel method allowed for instantaneous resistance observations in lab-scale along with the pressure response. The performance of the monitoring technique provided a new dimension in understanding foam flooding. This was integrated to provide comprehensive analysis of the formulated foam. Our innovative method provides the capability of quicker screening to successfully generate foam
Wei, Bing (Southwest Petroleum University) | Li, Qinzhi (Southwest Petroleum University) | Li, Hao (Southwest Petroleum University) | Lu, Laiming (Southwest Petroleum University) | Pu, Wanfen (Southwest Petroleum University)
The environmental issues of the traditional oilfield chemistries are challenging the Enhanced Oil Recovery (EOR) industry. Therefore, eco-friendly chemical EOR methods must be quickly developed. In this work, an abundant natural polymer on earth, nano-cellulose, was extracted from the plant-based materials and then introduced to EOR. On the basis of the original nano-cellulose, a series of surface-grafting were performed for the interest to make it more favorable for EOR application, thus generating the well-defined nano-cellulose based nano-fluids. The EOR related properties including morphology, thermal stability, rheology,
Water-soluble polymers have been widely used in chemical enhanced oil recovery (EOR) either independently or part of surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) processes. The polymer viscosifies the injected water thereby reducing displacing fluid mobility and sweep efficiency. Key to efficient sweep is attaining a sustainable mobility control (i.e. maintenance of sufficient viscosity during the propagation in the reservoir). Therefore, long-term stability is a crucial parameter in screening of appropriate polymers for EOR application, especially in high temperature and high salinity reservoirs. Generally, the evaluation of polymer solution's long-term stability is time-consuming process. Accordingly, there is a need to develop fast and reliable means to assess the feasibility of polymers from a long-term stability standpoint. Different from the methods in the literature, this paper presents a new facile approach to evaluate the polymers in powder form and identify their molecular decomposition. The approach is correlated and confirmed against conventional long-term stability results obtained on polymer solutions.
Thermogravimetric analysis (TGA) was used in this work to study the decomposition of polymers and their individual constituents. The derivative of TGA curve with respect to temperature is known as the DTG, which can clearly identify differences in decomposition rates of screened polymers. Furthermore, conventional long-term stability tests were performed on polymer solutions prepared in synthetic seawater with salinity of 57,670 ppm. The solutions were aged at a temperature of 95°C under anaerobic conditions and monitored by rheological measurements for viscosity loss, total organic carbon (TOC) analyses for material loss, and gel permeation chromatography (GPC) for molecular weight loss.
The thermal stability of 12 commercial water soluble polymers was tested in this work. The long-term stability results are consistent with the TGA results. The two polymers showing good thermogravimetric thermal stability exhibited significant viscosity retention in conventional long-term stability tests. TOC and GPC results further supported the TGA results. The developed and demonstrated method provides a fast approach to screen polymer candidates for high temperature and high salinity reservoirs.
Hongyan, Cai (State Key Laboratory of EOR, RIPED, CNPC) | Yi, Zhang (State Key Laboratory of EOR, RIPED, CNPC) | Jianguo, Li (State Key Laboratory of EOR, RIPED, CNPC) | Maozhang, Tian (State Key Laboratory of EOR, RIPED, CNPC) | Wenli, Luo (State Key Laboratory of EOR, RIPED, CNPC)
Presently, water flooding low permeability reservoirs face severe development challenges, such as early water breakthrough, low productivity, and low recovery. In view of this, a CEOR method combined by warmlike micelle and surfactant imbibition was recommended and detailed in-lab evaluations were performed.
Warmlike micelle (WLM) made from viscoelastic surfactant (VES) has special rheological characteristics, showing great potential for swept volume increasing through viscosifying effect in low permeability reservoirs. Some surfactants can induce spontaneous imbibition through capillary force effect, wettability alteration, and oil film removal to enhance recovery. Herein, warmlike micelle and surfactant imbibition were combined to both increase swept volume and induce spontaneous imbibition.
Rheological properties, imbibition recovery, and core flooding performance were evaluated for a reservoir with average permeability of 3.51 ×10-3μm2. At shear rate of 7.34 s-1, the viscosity of 0.30% VES solution amounted to 25.4 mPa.s at 70 °C. Static imbibition test by outcrop showed imbibition recovery of 68.7% was achieved by surfactant AEC. After that, three runs of core flooding tests were conducted to evaluate the performance of prepared formulations. For VES only formulation, an incremental recovery of 8.50% was obtained after water flooding with recovery of 32.81%. For the combined VES and surfactant imbibition formulation, 14.82% incremental recovery was achieved. Synergistic effect of VES and spontaneous imbibition motivated more remaining oil because of dual effects.
The developed CEOR method takes advantages of VES and imbibition, demonstrating promising potential for further development of low permeability reservoir.